Although each electric power generator that is connected to the Electricity Transmission and Distribution Network or “Grid” may function individually, each generator is constrained by one key parameter that makes it a part of a team of generators. The key factor that is common to the Grid and all individual generators is the frequency. Although the grid frequency changes, the goal is for it to be maintained within a narrow range for transmission network system stability. Normal allowable variations of the Grid frequency are limited to a very small range of ±0.5 Hz or less. With this in mind, it can be surmised that at any point in time all of the generators connected to the Grid run at the same speed or in a “synchronized” mode.
To maintain frequency stability, 50 Hz Grid codes as a standard mandates an increase in generated output of 4%-6% in 4-5 seconds when the frequency falls below a certain value, for example, 49.5 Hz for a 50 Hz system. These codes also stipulate that power output must be maintained down to a predetermined value, for example, 48.5 Hz for a 50 Hz system. In addition, if any further decrease in frequency occurs, below this value a decrease in generated output of 5 percent at a frequency of 47 Hz is provided for machine protection, Grid recovery and stability. Those skilled in the art will appreciate that this concept also holds true for a 60 Hz system with a typical 1% frequency regulation requirement where the low frequency classification comprises a frequency ranging from 57.8 Hz to about 59.5 Hz.
A frequency that is not a fixed value can be simply explained as the change in direction of the current flow in an AC (alternating current) system. Grid frequency is directly linked to the speed of rotation of the generators and is also indicative of normal fluctuations in the balance between power generation and consumption. For example, the generators on 50 Hz systems rotate at a speed of 3000 rpm because the rotor in the generator has two poles and thus 3000 rpm is 50 revolutions per second, or in every second the single magnetic field cuts the stator coils 50 times.
If several of the turbine generators cannot increase speed due to capacity limitations, other generators on the Grid will be required to compensate. When all the generators reach their Grid supply/contribution capacity limitation, or if there is a loss of generation or a large increase in load, the Grid can start operating at a lower frequency. This is an indication that the Grid is overloaded and demand/generator output changes are required to maintain Grid stability. In turn, a decrease in rotational speed results in reduced volumetric flow/mass-flow by the gas turbine compressor and a reduction in gas turbine output. When this situation occurs, appropriate measures are typically implemented immediately to compensate for this behavior.
For example, to meet under-frequency induced power output increase requirements, gas turbine OEMs have utilized several measures that can be implemented at short notice to increase power output. The standard approach is to rapidly open the Inlet Guide Vanes (IGVs) on the compressor while simultaneously increasing fuel flow to increase turbine speed. However, this traditional response can only provide limited increase in power of approximately 1%-2% and depends on the loading of the turbine generator—base load or part load—at the time of the disturbance, and the turbine's ability to exceed its firing limitations by peak or over firing.
Gas turbines are generally connected to the electrical power grid/network in droop mode (4% standard) with the primary goal of supplying adequate power and maintaining the Grid frequency within set operating limits for Grid operational stability. Grid instabilities attributable to large losses or additions in connected generation or loads have a significant impact on the Grid frequency. Depending on the nature of the load or generation change, the system frequency will either increase or decrease. In droop mode, these changes in the Grid frequency will cause the gas turbine to either increase or decrease power production in order to maintain the desired grid frequency.
As the connected electrical load on the Grid increases, the generators tend to operate at a lower speed. This is compensated for by regular frequency control measures like the gas turbine controls supplying more fuel to the turbines while adjusting air flow to the compressor, thereby increasing the speed. For example, prior art under frequency response systems utilize the intrinsic benefits of wet compression to achieve power augmentation through increased mass flow derived by injection of water into the Compressor Discharge Chamber (CDC) and/or combustion system to increase air mass flow and to reduce air temperature. The cooling effect makes the air denser so as to enhance the compression ratio through “wet compression.” The turbine may then run at full speed with artificially increased air density to achieve power augmentation.
In wet compression systems, the turbine controls are configured so that in conjunction with the simultaneous fuel and air increase, a spray of demineralized water is temporarily injected at the compressor inlet whenever there is a grid disturbance that requires additional power generation. The evaporation of the demineralized water cools the air flow entering the compressor inlet. The mass of this injected demineralized water increases the air density and consequently the mass flow through the compressor because of this cooling. However, rapid activation of these types of systems constitutes a challenge for the control systems to maintain optimum control because the increase in power output can only take effect at short notice if the gas turbine control and the water injection are perfectly coordinated. Moreover, conventional air flow augmentation systems do not generally augment the air flow fast enough to satisfy the above-mentioned standard mandates for response timing.
GE Patent Application No. 2008/0047275 A1 describes a control scheme to eliminate response lag due to changes in compressor air flow. The system determines a deviation of a Grid frequency from the standardized Grid frequency value and adjusts fuel flow from a portion of the fuel circuits while maintaining a substantially constant air flow from the compressor to facilitate control of the fuel to compressor discharge pressure ratio such that the combustor state does not lag changes in air flow when the combustor responds to the grid frequency deviation and so that the combustion flame is not lost.
During a Grid over-frequency event, fuel flow to the gas turbine is reduced to enable the turbine to meet the reduced power requirements of the Grid. Alternatively, a decrease in grid frequency attributable to lost generation or addition of a large load may result in an under-frequency event. To remedy this situation, the gas turbine will produce more power to stabilize the Grid. In such an event, fuel flow to the gas turbine must be increased to prevent instability within the gas turbine.
When a gas turbine operating at its maximum output capability is connected to the Grid, its ability to provide additional active power to support the Grid during an under frequency condition is limited. In such a situation, when the gas turbine is at its “maximum capability,” it will have to be over fired or peak fired to meet the mandated percentile output increase grid support requirement. However, over firing a turbine has a detrimental impact on emission compliance combustion stability, and Hot Gas Path (HGP) component life through, for example, negative impact on the metallurgy of the turbine's internal components.
Frequency regulation and Grid Response Margin are mandated by numerous regulatory bodies globally. This margin is typically accomplished by peak firing the gas turbine above base load, to enable delivering 2-5% additional output above the nominal base load rating based on cycle configuration (simple or combined cycle). However, in some cases, the gas turbines are not capable of peak fire and a substantial percentage of these units are required to be de-rated below base-load capability in order to comply with the regional grid codes. For example, in order not to over fire a gas turbine to meet the needs of the Grid in under frequency conditions, it is common to de-rate the gas turbines to facilitate having a reserve margin (e.g., 5%) to allow boosting when needed to meet the fast power generating ramp rate for grid under frequency requirements. However, de-rating the gas turbines results in reduced efficiencies for the gas turbines and is thus costly and generally undesirable.
An improved method and system to enhance the under frequency Grid response capability of gas turbines and, more particularly, methods and systems for operating a gas turbine to provide improved faster grid under frequency support without de-rating the gas turbines is thus desired.